U.S. patent number 5,958,365 [Application Number 09/104,511] was granted by the patent office on 1999-09-28 for method of producing hydrogen from heavy crude oil using solvent deasphalting and partial oxidation methods.
This patent grant is currently assigned to Atlantic Richfield Company. Invention is credited to Stephen K. Liu.
United States Patent |
5,958,365 |
Liu |
September 28, 1999 |
Method of producing hydrogen from heavy crude oil using solvent
deasphalting and partial oxidation methods
Abstract
Heavy crude oil is recovered and processed at a refinery through
(a) a distillation zone(s), (b) a solvent deasphalting unit (c ) a
high pressure air partial oxidation gasifier to produce a CO-rich
gas mixture including hydrogen, (d) a shift reactor and (e) a
purification step to produce 99.9% pure hydrogen. The hydrogen is
used to treat a deasphalted oil fraction and distillate hydrocarbon
fractions obtained from the crude oil. The process is considered
integrated in the sense that the purified hydrogen recovered from
the heavy crude oil is used to treat hydrocarbons recovered from
the same crude oil.
Inventors: |
Liu; Stephen K. (Bellingham,
WA) |
Assignee: |
Atlantic Richfield Company (Los
Angeles, CA)
|
Family
ID: |
22300885 |
Appl.
No.: |
09/104,511 |
Filed: |
June 25, 1998 |
Current U.S.
Class: |
423/655; 166/267;
208/41; 252/373; 166/50; 208/86; 208/226; 208/92 |
Current CPC
Class: |
C01B
3/48 (20130101); C01B 3/36 (20130101); C10G
45/02 (20130101); C01B 2203/0485 (20130101); C01B
2203/0475 (20130101); C01B 2203/1247 (20130101); C01B
2203/046 (20130101); C01B 2203/0415 (20130101); C01B
2203/1258 (20130101); C01B 2203/045 (20130101); C01B
2203/0283 (20130101); C01B 2203/065 (20130101); C01B
2203/147 (20130101); C01B 2203/0877 (20130101); C01B
2203/049 (20130101); C01B 2203/0894 (20130101); C01B
2203/0465 (20130101); Y02P 20/129 (20151101); C01B
2203/0255 (20130101); C01B 2203/043 (20130101); C01B
2203/84 (20130101) |
Current International
Class: |
C01B
3/00 (20060101); C01B 3/48 (20060101); C01B
3/36 (20060101); C10G 45/02 (20060101); C01B
003/12 (); C10C 003/00 (); C07C 001/02 (); E03B
003/11 () |
Field of
Search: |
;423/655 ;208/226,86,92
;252/373 ;166/50,267 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Other References
"FW Solvent Deasphalting" by F.M. Van Tine and Howard M. Feintuch,
"Handbook of Petroleum Refining Processes", 2nd Ed., by Robert A.
Meyers, Chapter 10.2; McGraw Hill, 1997. .
Design Considerations for Utility Size CFB Steam Generators, James
E. Maitland, Richards S. Skowyra, Bruce W. Wilhelm., Power-Gen'94,
Dec. 7-9-1994 7th International Conference & Exhibition for the
Power Generating Industries, Book III, pp. 45-47. .
Using Low Cost Petroleum Coke to Produce Electricity: Jack L.
Cotton, Jr. Sales Manager, Pyropower Corporation, Power-Gen'94,
Dec. 7-9-1994 7th International Conference & Exhibition for the
Power Generating Industries, Book III, pp. 72-92. .
Six Years of ABB-CE, Petcoke and Fluid Beds: Mike Tanca, Senior
Consulting Fluidized Bed Engineer, Combustion Engineering Inc.
Power-Gen'94, Dec. 7-9-1994 7th Intenational Conference &
Exhibition for the Power Generating Industries, Book III, pp.
94-116. .
Combustion Fossil Power Systems, A Reference Book on Fuel Burning
and Steam Generation: Joseph G. Singer, 1981, chapter 24, pp.
19-28. .
"Air Partial Oxidation" by Surinder M. Marria, Chief Process
Engineer, Foster Wheeler USA Corporation, Clinton New Jersey; for
Presentation at the Foster Wheeler Hydrogen Plant Conference,
Orlando, Florida, Jun. 1992..
|
Primary Examiner: Killos; Paul J.
Assistant Examiner: Parsa; J.
Attorney, Agent or Firm: Scott; F. Lindsey
Claims
What is claimed:
1. A process for refining a heavy crude oil comprising the steps
of
(a) producing the heavy crude oil from a subterranean
formation;
(b) transporting the heavy crude oil to a refinery
(c) passing a stream of the heavy crude oil through at least one
distillation zone to produce at least one overhead distillate
hydrocarbon stream and a heavier bottoms stream;
(d) deasphalting he bottoms stream to produce a deasphalted oil
stream, the deasphalted stream containing substantial quantities of
gas, oil and an asphaltic residue stream;
(e) partially oxidizing the asphaltic residue stream in a high
pressure, high temperature gasifier to produce a synthesis gas
comprising H.sub.2, H.sub.2 S, CO, CH.sub.4 and N.sub.2, wherein at
least 80% of the carbon in the asphaltic residues stream is
converted to CO;
(f) passing the synthesis gas through a CO-shift reactor to convert
the CO therein to H.sub.2 by reacting the CO with steam to produce
a gas mixture effluent;
(g) purifying the gas mixture effluent from step (f) to produce a
gas stream of at least 95% pure hydrogen with at least part of the
hydrogen being used to treat the deasphalted oil stream; and
(h) using at least part of the gas stream of step (g) in a
hydrotreating process.
2. The process of claim 1 wherein the distilling zones include an
atmospheric distillation zone and a vacuum flash zone.
3. The process of claim 2 wherein the overhead distillate stream of
step (c) has a boiling range at atmospheric pressure of below about
770.degree. F. and the overhead stream from the vacuum flash zone
has a boiling range of up to 1060.degree. F. at the pressure of the
vacuum flash zone.
4. The process of claim 1 wherein the partial oxidizing step is
carried out in the gasifier at a pressure of between about 400 psi
to about 1200 psi.
5. The process of claim 4 wherein the partial oxidizing step is
carried out at a temperature between about 1300.degree. C. and
1400.degree. C.
6. The process of claim 1 wherein the partial oxidation of step (e)
converts substantially all of the carbon in the asphaltic residue
stream to CO.
7. The process of claim 1 wherein the partial oxidation step is
carried out using air.
8. The process of claim 1 wherein the deasphalting is by solvent
deasphalting.
9. The process of claim 1 wherein the purifying step comprises
removing H.sub.2 S, CO.sub.2, N.sub.2 from the effluent of the
CO-shift reactor.
10. The process of claim 9 and further comprising the step of
processing the removed H.sub.2 S to produce sulfuric acid.
11. The process of claim 1 wherein the distillation zone produces
at least two overhead hydrocarbon streams.
12. The process of claim 1 wherein the heavy crude oil contains
substantial amounts of sulfur.
13. The process of claim 1 wherein the purification step (g)
produces H.sub.2 of at least a 99.0% purity.
14. The process of claim 1 wherein the purification in step (g)
produces H.sub.2 of at least 99.9% purity.
15. A method of producing hydrogen at a refinery and using the
hydrogen so produced in hydrotreating operations in the refinery,
said method comprising the steps of
(a) producing a heavy crude oil from a subterranean formation;
(b) transporting the heavy crude oil to a refinery;
(c) passing the heavy crude oil at the refinery through an
atmospheric distillation zone to produce a distillate hydrocarbon
overhead stream having a boiling range below about 770.degree. F.
and a heavier bottoms stream having a boiling range above about
710.degree. F.;
(d) passing the overhead stream through a hydrotreating unit;
(e) passing the bottoms stream to a deasphalting unit to separate
the bottoms stream into a deasphalted oil stream, the deasphalted
stream containing substantial quantities of gas, oil and an
asphaltic residue stream;
(f) passing the deasphalted oil stream to a hydrotreating unit;
(g) passing the asphaltic residue stream to a high pressure, high
temperature, air partial oxidation gasifier to partially oxidize
the stream into a CO-rich synthesis gas stream;
(h) passing the synthesis gas stream through a CO shift reactor to
convert CO contained therein to H.sub.2 ;
(i) purifying the gas stream leaving the CO shift reactor to at
least 99% pure hydrogen; and
(j) passing the purified gas stream to said hydrotreating units,
wherein the hydrocarbon streams passing therethrough are
hydrotreated with at least a portion of the hydrogen being used to
treat the deasphalted oil stream.
16. A method of producing hydrogen at a refinery and using the
hydrogen so produced in hydrotreating operations in the refinery,
said method comprising the steps of
(a) producing a heavy crude oil from a subterranean formation;
(b) transporting the heavy crude oil to a refinery;
(c) passing the heavy crude oil at the refinery through an
atmospheric distillation zone to produce at least one distillate
hydrocarbon overhead stream having a boiling range therein below
about 770.degree. F. and a heavier bottoms stream having a boiling
range therein of above about 710.degree. F.;
(d) passing the overhead stream of step (c) through a hydrotreating
unit;
(e) passing the bottoms stream to a vacuum flasher to produce an
overhead hydrocarbon stream having a boiling range up to about
1060.degree. F. and a bottoms hydrocarbon stream having a boiling
range above about 750.degree. F.;
(f) passing the overhead stream of step (e) through a hydrotreating
unit;
(g) passing the bottoms stream to a deasphalting unit to separate
the bottoms stream into a deasphalted oil stream, the deasphalted
oil stream containing substantial quantities of gas, oil and an
asphaltic residue stream;
(h) passing the deasphalted oil stream to a hydrotreating unit;
(i) passing an asphaltic residue stream to a high pressure, high
temperature partial oxidation gasifier to partially oxidize the
stream into a synthesis gas stream containing at least 80 volume %
CO;
(j) passing the synthesis gas stream through a CO shift reactor to
convert at least part of the CO contained therein to H.sub.2 ;
(k) purifying the synthesis gas stream to at least 99.0% pure
hydrogen; and
(l) passing the purified gas stream to said hydrotreating units,
wherein the hydrocarbon streams passing therethrough are
desulfurized with at least a portion of the hydrogen being used to
treat the deasphalted oil stream.
17. The method of claim 9 wherein the purification step comprises
the sequential removal of H.sub.2 S, CO.sub.2 and N.sub.2 from the
synthesis gas stream.
18. The method of claim 16 wherein the partial oxidation step in
the gasifier is carried out using pressurized, preheated air.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to a method of producing hydrogen for use in
a refinery processing heavy crude oil. In one aspect, the invention
relates to a method of producing hydrogen by processing the bottoms
of a solvent deasphalting process into hydrogen using partial
oxidation methods. In another aspect, the invention relates to an
integrated system for producing hydrogen from the bottoms of a
solvent desasphalting system in a refinery and using the H.sub.2 in
the hydroprocessing operations of the refinery.
2. Description of Related Art
Heavy crude oil is generally produced in remote locations, making
it impractical to refine the oil at those locations. In such
instances, the heavy crude oil is generally transported to a
refinery where the crude oil is refined into useful products such
as naphtha, kerosene, diesel fuel, fuel oils, gasoline, lube oil,
and the like. ("Heavy crude oil" is defined as an oil having an API
gravity of about 6 to about 20 API and a high asphaltene
content.)
There is a need for large amounts of cheap hydrogen in the refining
of heavy crudes. These crudes generally contain large amounts of
sulfur, and must be desulfurized which is generally done by
hydrogen treatments. The primary product of heavy crude is gas oil
which requires significant hydrotreating or hydroprocessing which
also uses large amounts of hydrogen. Other refinery operations that
use hydrogen are treatments to remove nitrogen, oxygen compounds
and to saturate olefins. Moreover, the hydrocracking of the large
molecules in the heavy oil requires large amounts of hydrogen.
U.S. patent application Ser. No. 08/927,427, filed Sep. 11, 1997,
and entitled "Method for Transporting a Heavy Crude Oil Produced
via a Wellbore from a Subterranean Formation to a Market Location
and Converting it into a Distillate Product Stream Using a Solvent
Deasphalting Process" discloses a method for treating heavy crude
where deasphalted heavy crude bottoms are used as a fuel to
generate steam in a boiler like reactor for use in the crude
distillation and deasphalting operations and for generating of
electricity. The flue gas from the fuel combustion is further
treated in a water shift reactor to produce hydrogen for use in
refining operation such as hydrogenation. However this process
produces relatively small amounts of hydrogen because the flue gas
contains only small amounts of CO which is the reactant in the
water shift reaction to produce the H.sub.2.
SUMMARY OF THE INVENTION
The method of the present invention, in one aspect, involves an
integrated system for producing hydrogen from heavy crude oil and
using the hydrogen so produced in the treatment of distillation
products of the heavy crude.
The process comprises five basic steps: (1) distilling a heavy
crude oil by atmospheric or vacuum distillation into at least one
overhead light hydrocarbon stream and a heavier bottom stream, (2)
deasphalting the bottoms stream by solvent deasphalting to produce
a deasphalted oil stream and an asphaltic residue stream, (3)
partially oxidizing the asphaltic residue steam in a high pressure,
high temperature gasifier, preferably an air partial oxidation
gasifier, to produce a CO-rich synthesis gas stream, (4) generating
and purifying hydrogen from the CO-rich synthesis gas stream, and
(5) treating a hydrocarbon stream, preferably the deasphalted oil
stream with the hydrogen.
The process of the present invention has particular application in
the processing of heavy crude oil because (a) heavy crude oil
yields a large amount of low value bitumen which can be used to
produce hydrogen, and (b) there is a need for large amounts of
hydrogen for treating the heavy oil. The process, in a preferred
embodiment, is thus an integrated system for generating hydrogen
from a heavy crude and using the hydrogen so generated in the
treatment of products from the same crude.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic diagram of an oil well penetrating a heavy
crude oil-bearing subterranean formation for the production of a
heavy crude oil.
FIG. 2 is a schematic diagram of the preferred embodiment of the
process of the present invention illustrating the process steps of
atmospheric and vacuum distillation, solvent deasphalting,
gasification, purification, and hydrogen treating.
DESCRIPTION OF THE PREFERRED EMBODIMENT
In the discussion of the Figures the same numbers will be used
throughout to refer to the same or similar components. Pumps,
valves and the like necessary to achieve the described process
flows and the like are considered to be well known to the art and
have not been shown.
Heavy Oil Producing Well
In FIG. 1 a well 10 is shown extending from a surface 12 through an
overburden 14 and penetrating an oil-bearing formation 16. Well 10
comprises a wellbore 18 which includes a casing 20 which is
cemented in place with cement 22 through formation 16. Well 10 also
includes a well head 24 positioned on casing 20 as known to those
skilled in the art for the injection of fluids and the production
of fluids from well 10. Well 10 also includes a tubing 26
positioned in casing 20 and extending into formation 16 to a depth
sufficient for the production of heavy crude oil from formation 16.
The heavy crude oil flows into a lower end 28 of tubing 26 and
upwardly through wellbore 10 either under formation pressure or
with pumping.
Casing 20 includes perforations 30 penetrating formation 16 so that
fluid communication is accomplished between formation 16 and the
inside of casing 20. Heavy crude oil recovered through tubing 26
flows upwardly and as shown schematically, flows through tubing 26
into a pipeline 32 for transportation to a refinery. Transportation
may also include shipment by tanker.
If necessary a diluent may be injected into casing 20 through a
line 36 as shown by an arrow 38 and flows downwardly to admixture
with the heavy crude oil recovered through tubing 26.
Alternatively, a diluent may be mixed with the heavy crude oil in
pipeline 32 by adding the diluent to pipeline 32 via a line 40 as
shown by an arrow 42. A variety of techniques can be used for
admixing the diluent with either the heavy crude oil in pipeline 32
or the heavy crude oil in well 10. For instance a second tubing
(not shown) could be run to the bottom of well 10 for the injection
of diluent or diluent could be added to the heavy crude oil at any
point along the length of tubing 26. Such variations are considered
to be well known to those skilled in the art and have not been
shown. The use of wells such as well 10 for the recovery of heavy
crude oils from subterranean formations is considered to be well
known to those skilled in the art.
The diluent may be a distillate hydrocarbon diluent which may be
produced in a crude oil distillation unit or a vacuum flasher or by
a combination of distillable hydrocarbons from a crude oil
distillation unit and a vacuum flasher. Any suitable miscible
material may be used as a diluent. The diluent is selected based
upon the requirements for diluent properties, the value of the
material used as a diluent and the like.
Distillation Units
In FIG. 2 a crude oil distillation unit 50 is shown at a refinery.
A heavy crude oil (generally as a crude oil/diluent mixture) piped
or transported to the refinery is charged to crude oil distillation
unit 50 through a line 52 and distilled in unit 50 to produce a
distillate hydrocarbon stream (e.g. naphtha) recovered through a
line 54 and a bottom stream recovered through a line 56. The crude
oil may also be used in a heater (not shown) to supply heat to unit
50 in a manner well known in the art. Also recovered in unit 50 are
middle distillate products through lines 55 and 57.
The distillation in unit 50 typically separates distillable
hydrocarbon materials which are readily separable from the crude
oil at atmospheric pressure from the heavier portions of the crude
oil. The distillation end point is a function of the crude oil feed
to unit 50 and a variety of other factors known to those skilled in
the art. Typically, the materials recovered as distillates have
boiling ranges below about 710 to about 770.degree. F. at
atmospheric pressure. Such materials include light hydrocarbons and
distillate products such as naphtha, stove oil, medium distillates
such as kerosene, diesel, gas oil and the like.
The bottoms stream in line 56 is passed to a vacuum flasher 142. In
vacuum flasher 142 the heavy hydrocarbonaceous stream recovered
through line 56 is distilled under a relatively high vacuum, i.e.
typically from about 2 to 4 inches of water, with additional
distillate material (e.g. gasoil) being recovered overhead through
line 144. The distillate material recovered through line 144
typically has a boiling range between about 750.degree. F. to about
1060.degree. F. at the reduced pressure in vacuum flasher 142. Such
materials are generally referred to as heavy gas oils or vacuum
gasoil and are suitably fed to further refining in a unit such as a
fluidized catalytic cracking unit, a fixed bed hydrocracking unit
or the like. The heat required in the vacuum flasher 142 may be
supplied by a heater fueled by the heavy crude oil or other energy
source available at the refinery. The heavy residual
hydrocarbonaceous stream having a boiling point above about
750.degree. F. to about 1060.degree. F. recovered from vacuum
flasher 142 via a line 146 is a stream which is frequently used as
asphalt, fed to a delayed petroleum coker to produce petroleum
coke, blended with a heavy distillate hydrocarbon stream and
marketed as a heavy fuel or the like. This stream still contains
valuable distillable hydrocarbon materials which are not separated
by vacuum distillation. These materials are, however, readily
recovered by a solvent deasphalting process. Accordingly, the heavy
hydrocarbonaceous residue resulting from the vacuum distillation
operation is passed through a line 146 to solvent deasphalting unit
62.
Deasphalting Unit
The bottoms stream recovered from vacuum flasher 142 through line
146 is passed to a solvent deasphalting unit 62. The bottoms stream
in line 146 is mixed with a suitable solvent from line 64. The
solvent is typically a paraffinic hydrocarbon solvent comprising
paraffins containing from about 3 to about 7 carbon atoms. The use
of such processes is well known to those skilled in the art as
shown, for instance, in "Handbook of Petroleum Refining Processes",
Robert A. Meyers, Editor in Chief, McGraw Hill, 1997, Chapter 10.2
"FW Solvent Deasphalting" by F. M. Van Tine and Howard M. Feintuch.
Solvent deasphalting processes are typically used as an extension
of vacuum distillation. The recovery of distillable hydrocarbons
from heavy hydrocarbonaceous streams by vacuum distillation is
dependent upon a boiling point distillation of the distillable
hydrocarbon materials. The recovery of distillable hydrocarbons
having a boiling point above about 1060.degree. F. at atmospheric
pressure by vacuum distillation requires distillation at
temperatures at which thermal cracking reactions occur at a speed
which makes such distillation separations impractical. As a result,
solvent deasphalting is used with such streams.
While solvent deasphalting is typically used after a vacuum
distillation step as illustrated in FIG. 2, solvent deasphalting
can also be used with the bottoms streams from an atmospheric
pressure crude oil distillation. The separation of distillable
hydrocarbons is accomplished by differences in solvent solubility
rather than by temperature distillation. This separation results in
the recovery of the more soluble materials from the heavy
hydrocarbon stream and produces a distillable stream which is
generally somewhat less reactive than the stream from a vacuum
distillation unit since it does not contain the olefins and other
reactive materials which result from cracking and which are
frequently found in vacuum distillation residues.
Solvent deasphalting unit 62 is any suitable counter-current
liquid/liquid contacting vessel. This vessel may be a stirred
vessel with a plurality of plates, a packed column or the like.
Since the solubility of the heavy oils in the paraffinic solvent is
reduced by increasing the temperature (i.e., decreasing the
density) of the paraffinic solvent, the temperature may be
increased in the upper portion of solvent deasphalting unit 62 for
reflux generation and the like. The temperature may be increased by
charging steam to deasphalting unit 62 through a line 82, as shown,
with spent steam being recovered through a line 84 and passed to
further heat exchange, recovery as spent steam and the like. In
such processes, a significant part of the process relates to the
recovery of the solvent used for the separation of the deasphalted
oil and the asphalt and asphaltene compounds. A variety of
techniques have been used for this solvent recovery varying from
distillation to super-critical separation. The super-critical
separation processes generally heat the paraffinic solvent to a
temperature such that its ability to dissolve the deasphalted oil
or the asphalt and asphaltene compounds (asphaltic residue) is
reduced to the point that a relatively pure solvent can be
recovered by liquid/liquid separation. Such recovery systems are
well known to those skilled in the art as discussed in the
"Handbook of Petroleum Refining Processes". In FIG. 2, the overhead
stream in line 66 which contains paraffinic solvent and deasphalted
oil is passed to a solvent recovery process 68. Solvent recovery
process 68 has been shown schematically and should be understood to
include a plurality of vessels as required to accomplish the
desired separation in the process selected for the separation. The
purified solvent is recovered through a line 70 and passed to
combination with the paraffinic solvent charged to solvent
deasphalting unit 62 through line 64. The deasphalted oil is
recovered and passed via line 72 to combination with the distillate
hydrocarbon stream from vacuum flasher 142 in line 144. A bottoms
stream is recovered from solvent deasphalting unit 62 which
contains asphalt, asphaltenes and other heavy residual compounds
(herein referred to as "asphaltic residue") and fed to a solvent
recovery process 76 via line 74 where the paraffinic solvent is
separated and recovered through a line 78 and passed back to
combination with the paraffinic solvent in line 70 with an
asphaltic residue being recovered through a line 80. It should be
understood that solvent recovery section 76 may also comprise a
plurality of vessels as required to accomplish the desired
separation as known to those skilled in the art. The asphaltic
residue is passed to gasifier 81 or a hydrogen production
system.
Hydrogen Production System
The hydrogen production system comprises (a) a partial oxidation
gas generator 81, (b) a heat recovery steam generator 82
(optional), (c ) a scrubber 83, (d) a CO shift reactor 84, (e)
H.sub.2 S, CO.sub.2 and N.sub.2 removal units 85, 86 and 87 and (f)
a pressure swing adsorption unit 88.
This process for producing hydrogen is based on the well known
pressure partial oxidation process and is particularly adapted to
the production of hydrogen from heavy crude oil. A variation of the
process, developed by Foster Wheeler USA Corp., is described in a
paper entitled "Air Partial Oxidation", presented at the Foster
Wheeler Hydrogen Plant Conference in Orlando, Fla. during June
1992, the disclosure of which is incorporated herein by reference.
The use of air instead of O.sub.2 in the partial oxidation offers
cost and safety advantages, and accordingly is the preferred medium
for use in the gas generator 81. The preferred pressure partial
oxidation process is a non-catalytic process.
The partial oxidation gasifier 81 is a substantially empty
refractory lined vessel equipped with a special burner for
promoting the reaction of air (or oxygen) with the asphaltic
residue entering the vessel from line 80. A well known and
commercial partial oxidation gasifier is marketed by Texaco Co.
The gasifier operates at a pressure of about 400 psi to about 1200
psi, typically about 500 psi to about 1000 psi, and a temperature
of about 1300.degree. C. to about 1400.degree. C. The partial
oxidation gasifier 81 converts at least 80%, preferably more than
90%, of the carbon in the gasifier hydrocarbon feed to CO. In the
most preferred embodiment, the high pressure partial oxidation
reaction in gasifier 81 converts substantially all of the carbon in
the asphalt residue entering the gasifier to CO.
Air is pressurized (50/60 bar) in compressor 91, preheated in
preheater 92 and passed to the gasifier 81 (i.e. gas generator)
through line 93. The asphaltic residue enters the top of vessel 81
and mixes with air and is partially combusted to form H.sub.2, CO,
and a small amount of CH.sub.4 (synthesis gas). Ash is removed from
vessel 81 through line 94. As indicated above, oxygen can be used
in the gasifier 81 instead of air. The synthesis gas from the
gasifier 81 is passed through a heat recovery steam generator 82
(for generating high pressure steam) and to a water-spray scrubber
83 via a line 95. In the scrubber 83, the gaseous stream is
quenched and scrubbed with recycled water to remove carbon
particles or soot through line 96.
From the scrubber 83, the synthesis gas is passed through a line 97
to the well known CO shift reactor 84, where carbon monoxide is
reacted with steam to produce H.sub.2. Shift reactors are
commercially available from several companies including Imperial
Chemical, Inc., Halder Topsoe, and KTI. Since the synthesis gas
entering the shift reactor 84 is CO rich, it is ideally suited for
H.sub.2 production:
From the CO shift reactor 84, the gas steam is passed through
several purification steps to remove H.sub.2 S, CO.sub.2 and
N.sub.2. As illustrated in FIG. 2, the gas mixture from reactor 84
flows through line 98 to the H.sub.2 S and CO.sub.2 removal units
85 and 86 which consist of a multi-stage amine (e.g. DEA, or
diethyl amine) scrubbing and absorber system. The first stage of
the amine absorber process removes H.sub.2 S and is a commercial
process available from various engineering firms, such as Eickmyer
and Associates, TPA. The H.sub.2 S is removed in unit 85 through
line 85a. Since H.sub.2 S is highly toxic, it must be treated and
converted to elemental sulfur for disposal/sale. Converting H.sub.2
S to elemental sulfur is a well known commercial process, and
design packages are available from firms such as Parsons and TPA.
The present invention, in one aspect, contemplates using the
H.sub.2 S stream to produce sulfuric acid using a wet sulfuric acid
process. Technology developed by Halder Topsoe is commercially
available (Halder Topsoe's WSA Process) for producing sulfuric acid
products. These products have important applications in the
alkylation process in refineries, as well as applications in
petrochemical and agricultural sectors. The asphaltic residues of
heavy crudes contain large amounts of sulfur (about 6%) and it is
thus very logical to incorporate the co-production of sulfuric
acid. The sulfuric acid can be used internally in the refinery's
alkylation unit to upgrade the light olefins from the FCC (Fluid
Catalytic Cracking) unit to produce high octane alkylates.
The desulfurized gas steam from the H.sub.2 S removal unit is then
passed through the second stage of the amine absorber system 86 to
remove the CO.sub.2. The CO.sub.2 removal unit 86 is a well proven
commercial process available for example from Eickmyer and
associates under trade designation Catacarb. The CO.sub.2 removed
can be stored and marketed, or vented to the atmosphere.
Nitrogen is separated from the stream by well known cryogenic
methods. Nitrogen cryogeneric separation technology is available
from Foster Wheeler. The basic separation comprises a heat
exchanger unit separator vessels. At the characteristic operation
pressure, the separation can be thermally sustained by the
Joule-Thomson refrigerative effect. An upstream molecular sieve
cleaning stage may also be used. The N.sub.2 removed can be stored
and marketed.
The H.sub.2 rich gas leaving the N.sub.2 separation stage is passed
to the final H.sub.2 process step via line 101. This stage is the
well known pressure swing adsorption unit 88 (PSA) which separates
H.sub.2 from N.sub.2, CO, CO.sub.2, moisture, and the like; and is
commercially available from several sources including U.O.P., Air
Products, Air Liquid, etc. The purity of H.sub.2 leaving the PSA
unit is typically in excess of 95%, preferably at least 99.0%, and
most preferably at least 99.9% pure.
The high purity H.sub.2 is passed to the hydrotreating units
through lines 102.
Hydrotreating
As mentioned above hydrogen is required in many refining
operations. Such operations include hydrocracking, hydrogeneration,
and hydrogen treating of the distilled products. Hydrogen treating
removes sulphur as H.sub.2 S, removes nitrogen or oxygens
compounds, and saturates olefins. These processes are referred to
herein as "hydrotreating" and are applied to straight run products,
feed to catalytic reforming, feeds for catalytic cracking and
hydrocracking and the like. As shown in FIG. 2 the hydrogen stream
is passed to four hydrotreating units 103, 104, 105 and 106 which,
respectively, receive distillate products from lines 54, 55, 57 and
144.
The distillate products flowing in lines 54, 55, 57 and 144 may
vary depending on the properties of the feed stream and operation
of the distillation units. The following are exemplary of a
distillation system for heavy crudes:
______________________________________ line 54 naphtha line 55
stove oil line 57 medium distillate line 144, and 72 gasoil
______________________________________
the hydrotreatment of these distillates is well known in the
art.
The gasoil from unit 106 may be further processed through fluid
catalytic cracking units (FCC). It is particularly important that
the feed to the FCC units be hydrotreated to remove the
contaminants described above.
The product outputs of hydrotreating units 103, 104 and 105 may be
processed further or piped to storage through lines 107, 108 and
109. The product output of FCC unit 110 may be piped to storage or
further processing through line 112.
Having thus described the invention by reference to certain of its
preferred embodiments, it is pointed out that the embodiments
described are illustrative rather than limiting in nature and that
many variations and modifications are possible within the scope of
the present invention. Many such variations and modifications may
be considered obvious and desirable to those skilled in the art
based upon a review of the foregoing description of preferred
embodiments.
* * * * *